Document/ExhibitDescriptionPagesSize 1: 10-Q Quarterly Report HTML 2.13M
2: EX-10.1 Material Contract HTML 1.64M
3: EX-31.1 Certification -- §302 - SOA'02 HTML 26K
4: EX-31.2 Certification -- §302 - SOA'02 HTML 26K
5: EX-32.1 Certification -- §906 - SOA'02 HTML 23K
6: EX-32.2 Certification -- §906 - SOA'02 HTML 23K
12: R1 Cover HTML 80K
13: R2 Condensed Consolidated Statements of Operations - HTML 130K
Unaudited
14: R3 Condensed Consolidated Statements of Comprehensive HTML 53K
Income (Loss) - Unaudited
15: R4 Condensed Consolidated Balance Sheets - Unaudited HTML 133K
16: R5 Condensed Consolidated Balance Sheets - Unaudited HTML 45K
(Parenthetical)
17: R6 Condensed Consolidated Statements of Cash Flows - HTML 125K
Unaudited
18: R7 Condensed Consolidated Statements of Equity - HTML 97K
Unaudited
19: R8 Condensed Consolidated Statements of Equity - HTML 26K
Unaudited (Parenthetical)
20: R9 Organization and Description of Business HTML 26K
21: R10 Summary of Significant Accounting Policies HTML 37K
22: R11 Acquisitions HTML 32K
23: R12 Revenue Recognition HTML 39K
24: R13 Derivative Instruments HTML 137K
25: R14 Property and Equipment, Net (Full Cost Method) HTML 39K
26: R15 Long-Term Debt HTML 46K
27: R16 Income Taxes HTML 27K
28: R17 Supplemental Balance Sheet Detail HTML 57K
29: R18 Fair Value Measurements HTML 77K
30: R19 Commitments and Contingencies HTML 37K
31: R20 Shareholders' Equity HTML 49K
32: R21 Share-Based Compensation and Other Benefit Plans HTML 57K
33: R22 Earnings Per Share HTML 52K
34: R23 Subsequent Events HTML 26K
35: R24 Summary of Significant Accounting Policies HTML 45K
(Policies)
36: R25 Acquisitions (Tables) HTML 28K
37: R26 Revenue Recognition (Tables) HTML 33K
38: R27 Derivative Instruments (Tables) HTML 138K
39: R28 Property and Equipment, Net (Full Cost Method) HTML 34K
(Tables)
40: R29 Long-Term Debt (Tables) HTML 42K
41: R30 Supplemental Balance Sheet Detail (Tables) HTML 56K
42: R31 Fair Value Measurements (Tables) HTML 70K
43: R32 Commitment and Contingencies (Tables) HTML 29K
44: R33 Equity (Tables) HTML 35K
45: R34 Share-Based Compensation and Other Benefit Plans HTML 52K
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46: R35 Earnings Per Share (Tables) HTML 50K
47: R36 Organization and Description of Business (Details) HTML 35K
48: R37 Summary of Significant Accounting Policies HTML 35K
(Details)
49: R38 Acquisitions - Narrative (Details) HTML 36K
50: R39 Acquisitions - Schedule of Pro Forma Information HTML 27K
(Details)
51: R40 Revenue Recognition (Details) HTML 37K
52: R41 Derivative Instruments - Commodity Derivative HTML 101K
Positions (Details)
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54: R43 Derivative Instruments - Impact of Derivative HTML 34K
Activities on Condensed Consolidated Statements of
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Instruments on Condensed Consolidated Balance
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56: R45 Property and Equipment, Net (Full Cost Method) - HTML 37K
Summary of Property and Equipment (Details)
57: R46 Property and Equipment, Net (Full Cost Method) - HTML 41K
Narrative (Details)
58: R47 Long-Term Debt - Summary of Long-Term Debt HTML 56K
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59: R48 Long-Term Debt - Narrative (Details) HTML 82K
60: R49 Income Taxes (Details) HTML 36K
61: R50 Supplemental Balance Sheet Detail (Details) HTML 82K
62: R51 Fair Value Measurements - Narrative (Details) HTML 34K
63: R52 Fair Value Measurements - Assets and Liabilities HTML 67K
Measured at Fair Value on Recurring Basis
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64: R53 Commitments and Contingencies - Narrative HTML 83K
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Commitment, Excluding Long-term Commitment
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(Address of principal executive offices) (Zip Code)
(i713) i722-6500
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
iClass
A Common Stock, $0.01 Par Value
iROCC
iThe Nasdaq Stock Market LLC
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☒ No ☐
Indicate by check mark whether the
registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☒ No ☐
Indicate by check mark whether the registrant
is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☐
iAccelerated
filer
☒
Non-accelerated filer
☐
Smaller reporting company
i☒
Emerging growth company
i☐
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No ☒
As
of July 29, 2022, there were 42,359,125 shares of common stock outstanding, including i19,810,127 shares of Class A Common Stock and i22,548,998
shares of Class B Common Stock.
Accounts
receivable, net of allowance for credit losses
i201,357
i118,594
Derivative
assets
i15,006
i11,478
Prepaid
and other current assets
i13,501
i20,998
Assets
held for sale
i11,400
i11,400
Total
current assets
i275,714
i186,151
Property
and equipment, net (full cost method)
i1,534,492
i1,383,348
Derivative
assets
i5,597
i2,092
Other
assets
i10,735
i5,017
Total
assets
$
i1,826,538
$
i1,576,608
Liabilities
and Equity
Current liabilities
Accounts payable and accrued liabilities
$
i299,221
$
i214,381
Derivative
liabilities
i144,541
i50,372
Current
portion of long-term debt
i1,897
i4,129
Total
current liabilities
i445,659
i268,882
Deferred
income taxes
i2,937
i2,793
Derivative
liabilities
i28,604
i23,815
Other
non-current liabilities
i9,858
i10,358
Long-term
debt, net
i565,329
i601,252
Commitments
and contingencies (Note 11)
i
i
Equity
Preferred
stock of $ii0.01/ par value – ii5,000,000/
shares authorized; iinone/ issued as of June
30, 2022 and December 31, 2021
i—
i—
Class
A common stock, $ii0.01/ par value – ii110,000,000/
shares authorized; ii20,483,112/ and ii21,090,259/
issued and outstanding as of June 30, 2022 and December 31, 2021, respectively
i205
i729
Class
B common stock, $ii0.01/ par value – ii30,000,000/
shares authorized; iiii22,548,998///
shares issued and outstanding as of June 30, 2022 and December 31, 2021
i2
i2
Paid-in
capital
i257,615
i273,329
Retained
earnings
i110,782
i49,583
Accumulated
other comprehensive loss
(i111)
(i111)
Ranger
Oil shareholders’ equity
i368,493
i323,532
Noncontrolling
interest
i405,658
i345,976
Total
equity
i774,151
i669,508
Total
liabilities and equity
$
i1,826,538
$
i1,576,608
See
accompanying notes to condensed consolidated financial statements.
5
RANGER OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED
In
October 2021, the Company effected a recapitalization, pursuant to which, among other things, the Company’s common stock was renamed and reclassified as Class A common stock, par value $i0.01 per share (“Class A Common Stock”), a new class of capital stock of the Company, Class B Common Stock, par value $i0.01
per share (“Class B Common Stock”) was authorized, and the designation of the Series A Preferred Stock was cancelled. See Note 12 in the notes to condensed consolidated financial statements for further details.
See accompanying notes to condensed consolidated financial statements.
7
RANGER OIL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – UNAUDITED
(in thousands, except per share amounts or where otherwise indicated)
i
Note 1 – Organization and Description of Business
Ranger Oil Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Ranger
Oil,” the “Company,”“we,”“us” or “our”) is an independent oil and gas company focused on the onshore development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. We operate in and report our financial results and disclosures as iione/
segment, which is the development and production of crude oil, NGLs and natural gas.
/
On January 15, 2021, the Company consummated the transactions (collectively, the “Juniper Transactions”) contemplated by: (i) the Contribution Agreement, dated November 2, 2020, by and among the Company, ROCC Energy Holdings, L.P. (formerly PV Energy Holdings, L.P., the “Partnership”) and JSTX Holdings, LLC (“JSTX”), an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek Resources, LLC,
“Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020, by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership pursuant to which Juniper contributed $i150 million in cash and certain oil and gas assets in South Texas in exchange for equity. See Note 2 for further discussion.
i
Note
2 – Summary of Significant Accounting Policies
iBasis of Presentation
Our unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries
is provided for in our condensed consolidated statements of operations and comprehensive income (loss) and our condensed consolidated balance sheets for the periods presented. Our condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the Securities Exchange Commission (the “SEC”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments considered necessary for a fair presentation of our condensed consolidated financial statements have been included. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. Our condensed consolidated financial statements should be read in conjunction with
the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2021. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
Significant Accounting Policies
The Company’s significant accounting policies are described in “Note 3 – Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in
this report should be read in conjunction with the Company’s 2021 Annual Report.
i
Principles of Consolidation
In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of Class B Common Stock which are non-economic voting only shares of the Company.
Juniper’s economic interest in the Company is held through its ownership of limited partner interests (the “Common Units”) in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization
with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.
The
Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects,
/
8
cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the
Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant. The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its i100%
controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company
determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s consolidated financial statements. The Company reflects a noncontrolling interest in the consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying condensed consolidated financial statements and represents the ownership interest held by Juniper in the Partnership.
i
Noncontrolling
Interest
The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of June 30, 2022, the Company owned i20,483,112
Common Units, representing a i47.6% limited partner interest in the Partnership, and Juniper owned i22,548,998 Common Units, representing the remaining i52.4%
limited partner interest. As of December 31, 2021, the Company owned i21,090,259 Common Units, representing a i48.3%
limited partner interest in the Partnership, and Juniper owned i22,548,998 Common Units, representing the remaining i51.7% limited partner
interest. During the three months ended June 30, 2022, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation.
When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under Accounting Standards Codification Topic 810, Consolidation, which requires that any
differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the common shareholders and noncontrolling interest pro rata based on ownership interests in the Partnership.
/i
Recent
Accounting Pronouncements
We consider the applicability and impact of all Accounting Standard Updates (“ASUs”). ASUs not listed below were assessed and determined to be not applicable.
Recently Issued Accounting Pronouncements Not Yet Adopted
In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business
combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application
rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.
9
i
Note 3 – Acquisitions
2022 Acquisitions
In June 2022, we completed acquisitions of additional working
interests in Ranger-operated wells along with certain contiguous oil and gas producing assets and undeveloped acreage in the Eagle Ford shale. The aggregate cash consideration for these acquisitions was $i46.0 million and are subject to customary post-closing adjustments. These transactions were accounted for as asset acquisitions. See Note 15 for discussion of acquisitions that closed subsequent to June 30, 2022.
Acquisition of Lonestar Resources
On
October 5, 2021 (the “Closing Date”), the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of the Company (the “Lonestar Acquisition”). The Lonestar Acquisition was effected pursuant to the Agreement and Plan of Merger (the “Merger Agreement”), dated July 10, 2021, by and between the
Company and Lonestar. In accordance with the terms of the Merger Agreement, Lonestar shareholders received i0.51 shares of the Company’s common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition. Based on the closing price of the Company’s common stock on October
5, 2021 of $i30.19, and in connection with the Lonestar Acquisition, the total value of the Company’s common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $i173.6 million.
The
Lonestar Acquisition constituted a business combination and was accounted for using the acquisition method of accounting, with Ranger Oil being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of Lonestar and its subsidiaries were recorded at their respective preliminary fair values as of the date of completion of the Lonestar Acquisition. Although the purchase price allocation is substantially complete as of June 30, 2022, there may be further adjustments to oil and gas properties as we continue to gather information related to the evaluation of certain properties. We will finalize these amounts within one year subsequent to the closing date of the Lonestar Acquisition. During the six months ended June 30, 2022, there were
no material changes to the allocation presented in the 2021 Form 10-K.
We expensed $i2.0 million in acquisition-related costs for the six months ended June 30, 2022 related to employee severance and change-in-control compensation costs and other integration related costs.
Pro Forma Operating Results (Unaudited)
i
The
following unaudited pro forma condensed financial data for the three months and six months ended June 30, 2021 was derived from the historical financial statements of the Company giving effect to the Lonestar Acquisition, as if it had occurred on January 1, 2020.
Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of gathering, processing and transportation
expense (“GPT”) in our condensed consolidated statements of operations.
NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have
determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues on a net basis with processing costs presented as a reduction of revenue.
10
Natural gas. Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is purchased by the processor or delivered to us at the tailgate of the midstream processing vendors’
facilities and sold to a third-party customer. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT in our condensed consolidated statements of operations.
Performance obligations
We record revenue in the month that our oil and gas production is delivered to our customers. However, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production sold. We
record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.
We apply a practical expedient which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts
do not create contract assets or liabilities.
Our accounts receivable consists mainly of trade receivables from commodity sales and joint interest billings due from partners on properties we operate. Our allowance for credit losses is entirely attributable to receivables from joint interest partners. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, our oil, natural gas, and NGL receivables are collected within 30 to 90 days. iThe
following table summarizes our accounts receivable by type as of the dates presented:
Accounts
receivable, net of allowance for credit losses
$
i201,357
$
i118,594
i
Note
5 – Derivative Instruments
We utilize derivative instruments, typically swaps, put options and call options which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not formally designated as hedges for accounting purposes. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase
the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes.
11
For our commodity derivatives, we typically combine swaps, purchased put options, purchased call options, sold put options and sold call options in order
to achieve various hedging objectives. Certain of these objectives result in combinations that operate as collars which include purchased put options and sold call options, three-way collars, which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap, among others.
Commodity Derivatives 1
i
The following table sets forth our commodity derivative positions,
presented on a net basis by period of maturity, as of June 30, 2022:
3Q2022
4Q2022
1Q2023
2Q2023
3Q2023
4Q2023
1Q2024
2Q2024
NYMEX
WTI Crude Swaps
Average Volume Per Day (bbl)
i3,000
i3,000
i2,500
i2,400
i2,807
i2,657
i462
i462
Weighted
Average Swap Price ($/bbl)
$
i73.01
$
i69.20
$
i54.40
$
i54.26
$
i54.92
$
i54.93
$
i58.75
$
i58.75
NYMEX
WTI Crude Collars
Average Volume Per Day (bbl)
i15,625
i12,636
i7,917
i6,181
i4,891
i2,446
Weighted
Average Purchased Put Price ($/bbl)
$
i59.22
$
i58.06
$
i55.79
$
i50.67
$
i70.00
$
i65.00
Weighted
Average Sold Call Price ($/bbl)
$
i84.70
$
i82.23
$
i74.85
$
i65.65
$
i92.37
$
i85.75
NYMEX
WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)
i7,337
i1,630
Weighted
Average Swap Price ($/bbl)
$
i1.172
$
i1.020
NYMEX
HH Swaps
Average Volume Per Day (MMBtu)
i12,500
i12,500
i10,000
i7,500
Weighted
Average Swap Price ($/MMBtu)
$
i3.745
$
i3.793
$
i3.620
$
i3.690
NYMEX
HH Collars
Average Volume Per Day (MMBtu)
i15,679
i14,511
i6,417
i11,538
i11,413
i11,413
i11,538
i11,538
Weighted
Average Purchased Put Price ($/MMBtu)
$
i3.088
$
i2.854
$
i6.000
$
i2.500
$
i2.500
$
i2.500
$
i2.500
$
i2.328
Weighted
Average Sold Call Price ($/MMBtu)
$
i4.141
$
i3.791
$
i10.000
$
i2.682
$
i2.682
$
i2.682
$
i3.650
$
i3.000
OPIS
Mt Belv Ethane Swaps
Average Volume per Day (gal)
i27,717
i27,717
i98,901
i34,239
i34,239
i34,615
Weighted
Average Fixed Price ($/gal)
$
i0.2500
$
i0.2500
$
i0.2288
$
i0.2275
$
i0.2275
$
i0.2275
_______________________
1 NYMEX
WTI refers to New York Mercantile Exchange West Texas Intermediate that serves as the benchmark for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. OPIS Mt Belv refers to Oil Price Information Service Mt. Belvieu that serves as the benchmark for ethane which represents a commodity proxy for NGLs. As of June 30, 2022, we also had i50,000 bbls/month of incremental WTI Long Calls at $i125/bbl
in August and September 2022 as well as i25,000 bbls/month of incremental WTI Long Puts at $i85/bbl in August and September 2022.
/
Interest
Rate Derivatives
Through May 2022, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate indebtedness. The notional amount of the Interest Rate Swaps totaled $i300 million, with us paying a weighted average fixed rate of i1.36%
on the notional amount, and the counterparties paying a variable rate equal to LIBOR. As of June 30, 2022, we did not have any interest rate derivatives.
12
Financial Statement Impact of Derivatives
The impact of our derivative activities on income is included within Derivatives on our condensed consolidated statements of operations. Derivative contracts that have expired at the end of a period, but for which cash had not been received or paid as of the balance sheet date, have been recognized as components of Accounts receivable (see Note 4) and
Accounts payable and accrued liabilities (see Note 9) on the condensed consolidated balance sheets. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded within the Derivative contracts section of our condensed consolidated statements of cash flows under Net losses and Cash settlements and premiums paid, net.
i
The
following table summarizes the effects of our derivative activities for the periods presented:
Interest
Rate Swap gains (losses) recognized in the condensed consolidated statements of operations
$
(i19)
$
i4
$
i64
$
i36
Commodity
losses recognized in the condensed consolidated statements of operations
(i44,923)
(i54,231)
(i212,893)
(i98,631)
$
(i44,942)
$
(i54,227)
$
(i212,829)
$
(i98,595)
Interest
rate cash settlements recognized in the condensed consolidated statements of cash flows
$
(i477)
$
(i956)
$
(i1,415)
$
(i1,878)
Commodity
cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows
(i74,037)
(i15,678)
(i102,507)
(i21,925)
$
(i74,514)
$
(i16,634)
$
(i103,922)
$
(i23,803)
/i
The
following table summarizes the fair values of our derivative instruments, which we elect to present on a gross basis, as well as the locations of these instruments on our condensed consolidated balance sheets as of the dates presented:
As
of June 30, 2022, we reported net commodity derivative liabilities of $i152.5 million. The contracts associated with these positions are with ieight
counterparties for commodity derivatives, all of which are investment grade financial institutions and are participants in our revolving credit facility (the “Credit Facility”). This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.
The agreements underlying our derivative instruments include provisions for the netting of settlements with the counterparties for contracts of similar type. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions.
Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.
See Note 10 for information regarding the fair value of our derivative instruments.
13
i
Note
6 – Property and Equipment, Net (Full Cost Method)
i
The following table summarizes our property and equipment as of the dates presented:
Accumulated
depreciation, depletion, amortization and impairments
(i1,138,571)
(i1,033,293)
Total
property and equipment, net
$
i1,534,492
$
i1,383,348
_______________________
/
1
Excludes the corporate office building and related assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of June 30, 2022 and December 31, 2021. We closed on the sale of the corporate office building in July 2022. See Note 15 for additional information on the sale.
Unproved property costs of $i54.0 million and $i57.9
million have been excluded from amortization as of June 30, 2022 and December 31, 2021, respectively. We transferred $i7.7 million and $i13.5
million of undeveloped leasehold costs, including capitalized interest, associated with proved undeveloped reserves, acreage unlikely to be drilled or expiring acreage, from unproved properties to the full cost pool during the six months ended June 30, 2022 and 2021, respectively. We capitalized internal costs of $i2.6 million and $i1.7
million and interest of $i2.2 million and $i1.6 million during the six months ended June 30, 2022 and 2021,
respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $i15.25 and $i12.82
for the six months ended June 30, 2022 and 2021, respectively.
Ceiling Test
Beginning in early 2020, certain events such as the COVID-19 pandemic and the decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) negatively impacted the oil and gas industry with significant declines in crude oil prices and oversupply of crude oil. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. A high level of uncertainty remains regarding the volatility of energy supply and demand as a result of OPEC’s continued strategy to increase production as well as the Russia-Ukraine conflict and related sanctions which began
in the first quarter of 2022. WTI crude oil and natural gas prices have surged with prices over $i120 per bbl and over $i9 per Mcf, respectively, during the first half of 2022 due to oil supply shortage concerns.
At the end of each
quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). Because the Ceiling Test utilizes commodity prices based on a trailing 12-month average, the first quarter of 2021 was impacted by the decline in commodity prices as a result of the COVID-19 and macroeconomic factors as discussed, resulting in an impairment of our oil and gas properties of $i1.8 million
during the three months ended March 31, 2021. iNo further impairments were recorded during the remainder of 2021. We did iino/t
record any impairments of our oil and gas properties during the three and six months ended June 30, 2022.
/
14
i
Note
7 – Long-Term Debt
i
The following table summarizes our debt obligations as of the dates presented:
1
The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. As of June 30, 2022 and December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 15 for additional information on the sale.
2 Other debt of $i2.2 million
was extinguished during the six months ended June 30, 2022 and recorded as a gain on extinguishment of debt.
3 The discount and issuance costs of the i9.25% Senior Notes due 2026 are being amortized over its respective term using the effective-interest method.
4 Excludes issuance costs associated with the Credit Facility, which represents costs attributable to the access to credit
over its contractual term, that have been presented as a component of Other assets (see Note 9) and are being amortized over the term of the Credit Facility using the straight-line method.
/
Credit Facility
As of June 30, 2022, the Credit Facility had a $i1.0
billion revolving commitment and an $i875 million borrowing base with aggregate elected commitments of $i400 million, and
a $i25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Our next borrowing base redetermination is expected to be in August 2022. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time
during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital.
In June 2022, we entered into the Agreement and Amendment No. 12 to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on June 1, 2022, (1) increase the borrowing base from $i725 million to $i875 million,
with aggregate elected commitments remaining at $i400 million and (2) replaced LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements.
The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from i1.50%
to i2.50%, determined based on the utilization level under the Credit Facility or (b) effective June 1, 2022, a term SOFR reference rate (a Eurodollar rate, including LIBOR prior to June 1, 2022), plus an applicable margin ranging from i2.50%
to i3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings is payable every one, three or isix
months, at the election of the borrower, and is computed on the basis of a year of 360 days. As of June 30, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was i4.98%. Unused commitment fees are charged at a rate of i0.50%.
/
15
The
Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of i1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter of i3.50
to 1.00.
The Credit Facility also contains other customary affirmative and negative covenants as well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.
As of June 30, 2022, we had $i171.0 million in outstanding borrowings and $i0.7
million in outstanding letters of credit under the Credit Facility. Factoring in the outstanding letters of credit, we had $i228.3 million of availability under the Credit Facility as of June 30, 2022. During the six months ended June 30, 2021, we incurred and capitalized approximately $i0.4
million of issue costs associated with amendments to the Credit Facility.
i9.25% Senior Notes due 2026
On August 10, 2021, our indirect, wholly-owned subsidiary completed an offering of $i400
million aggregate principal amount of senior unsecured notes due 2026 (the “i9.25% Senior Notes due 2026”) that bear interest at i9.25% and were sold at i99.018%
of par. Obligations under the i9.25% Senior Notes due 2026 were assumed by ROCC Holdings, LLC (formerly, Penn Virginia Holdings, LLC, hereinafter referred to as “Holdings”), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility.
Interest on the i9.25%
Senior Notes due 2026 is payable semi-annually in arrears on February 15 and August 15 of each year. We may redeem the i9.25% Senior Notes due 2026 at any time in whole or in part from time to time in part at specified redemption prices.
The indenture governing the i9.25%
Senior Notes due 2026 also contains other customary affirmative and negative covenants as well as events of default and remedies.
The income tax provision resulted
in an expense of $i1.3 million and an expense of $i1.1 million for the three and six months ended June 30, 2022, respectively.
The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of i0.9%, which is fully attributable to the State of Texas. Our net deferred income tax liability balance of $i2.9 million
as of June 30, 2022 is also fully attributable to the State of Texas and primarily related to property.
The income tax provision resulted in an expense of $i0.2 million and a benefit of $i0.1 million
for the three and six months ended June 30, 2021, respectively. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of i1.1%, which is fully attributable to the State of Texas.
We had iino/
liability for unrecognized tax benefits as of June 30, 2022 and December 31, 2021. There were iino/
interest and penalty charges recognized during the six months ended June 30, 2022 and 2021. Tax years from 2017 forward remain open to examination by the major taxing jurisdictions to which the Company is subject; however, net operating losses originating in prior years are subject to examination when utilized.
/
16
i
Note
9 – Supplemental Balance Sheet Detail
i
The following table summarizes components of selected balance sheet accounts as of the dates presented:
Deferred issuance costs of the Credit Facility, net of amortization
$
i2,920
$
i3,308
Right-of-use
assets – operating leases
i1,279
i1,671
Deposits
i6,411
i—
Other
i125
i38
$
i10,735
$
i5,017
Accounts
payable and accrued liabilities:
Trade accounts payable
$
i31,164
$
i32,452
Drilling
and other lease operating costs
i66,701
i35,045
Revenue
and royalties payable
i134,474
i95,521
Production,
ad valorem and other taxes
i15,882
i7,905
Derivative
settlements to counterparties
i23,135
i6,117
Compensation
and benefits
i5,547
i13,942
Interest
i14,310
i15,321
Environmental
remediation liability 3
i2,105
i2,287
Current
operating lease obligations
i874
i914
Other
i5,029
i4,877
$
i299,221
$
i214,381
Other
non-current liabilities:
Asset retirement obligations
$
i8,374
$
i8,413
Non-current
operating lease obligations
i547
i975
Postretirement
benefit plan obligations
i937
i970
$
i9,858
$
i10,358
_______________________
1 Includes
tubular inventory and well materials of $i10.4 million and $i9.5 million and crude oil volumes in storage of $i0.7 million
and $i0.8 million as of June 30, 2022 and December 31, 2021, respectively.
2 The balances as of June 30, 2022 and December 31, 2021 include $i0.8 million
and $i9.6 million, respectively, for the prepayment of drilling and completion materials and services.
3 The balance as of June 30, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition.
//
17
i
Note
10 – Fair Value Measurements
We apply the authoritative accounting provisions included in GAAP for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.
Our financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of June 30, 2022 and December 31, 2021, the carrying values of the borrowings outstanding under our credit facilities approximate fair value as the borrowings bear interest at variables rates tied to current
market rates and the applicable margins represent market rates. The fair value of our fixed rate i9.25% Senior Notes due 2026 is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of June 30, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $i579.6 million
and $i563.8 million, respectively. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $i619.0 million
and $i634.6 million.
Recurring Fair Value Measurements
The fair values of our derivative instruments are measured at fair value on a recurring basis on our condensed consolidated balance sheets. iThe
following tables summarize the valuation of those assets and (liabilities) as of the dates presented:
We
used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:
•Commodity derivatives: We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil, NYMEX HH natural gas and OPIS Mt Belv Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a Level 2 input.
•Interest rate swaps: In periods prior to May 2022, we determined the fair values of our interest rate swaps
using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input.
/
18
Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. See Note 5 for additional details on our derivative instruments.
i
Non-Recurring
Fair Value Measurements
The most significant non-recurring fair value measurements utilized in the preparation of our condensed consolidated financial statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties and certain share-based compensation awards. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as Level
3 inputs.
Gathering and Intermediate Transportation Commitments
We have long-term agreements that provide us with field gathering and intermediate pipeline transportation services for a majority of our crude oil and condensate production in Lavaca and Gonzales Counties, Texas. We also have volume capacity support for certain downstream interstate pipeline transportation. iThe following table provides details on these contractual arrangements
as of June 30, 2022:
Description of contractual arrangement
Expiration of Contractual Arrangement
Minimum Volume Commitment (MVC) (bbl/d)
Expiration of Minimum Volume
Commitment (MVC)
Field gathering agreement
February 2041
i8,000
February 2031
Intermediate pipeline transportation services
February
2026
i8,000
February 2026
Volume capacity support
April 2026
i8,000
April
2026
Each of these arrangements also contain an obligation to deliver the first iii20,000//
gross barrels of oil per day produced from Gonzales, Lavaca and Fayette Counties, Texas. For certain of our crude oil volumes gathered under the field gathering agreement, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of $i90 per bbl, the gathering rate escalates pursuant to the field gathering agreement.
Under each of the arrangements, credits for deliveries of volumes in excess of the
volume commitment may be applied to any deficiency arising in the succeeding 12-month period.
During the three months ended June 30, 2022 and 2021, we recorded expense of $i10.6 million and $i8.7 million,
respectively, and $i20.8 million and $i17.1 million during
the six months ended June 30, 2022 and 2021, respectively for these contractual obligations.
Excluding the application of credits earned during the 12-month period ended June 30, 2022 for deliveries of volumes in excess of the volume commitment, and the potential impact of the effects of price escalation from commodity price changes, if any, the minimum fee requirements attributable to the MVC under the gathering, transportation and marketing agreements are as follows: $i7.0
million for the remainder of 2022, approximately $iii13.9//
million per year for 2023 through 2025, $i7.8 million for 2026, $iiii3.8///
million per year for 2027 through 2030 and $i0.6 million for 2031.
Crude Oil Storage
As of June 30, 2022, we had access to up to approximately i180,000
barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. In addition, we had access for an additional i70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45 days’ notice to the counterparty. Costs associated with this monthly agreement are in the form of a monthly fixed rate short-term lease and are charged as incurred on a monthly
basis to GPT in our condensed consolidated statements of operations.
Other Agreements
We have a long-term dedication of certain specific leases under a crude purchase and throughput terminal agreement through 2032. Under the agreement, we have rights to transfer dedicated oil for delivery to a gulf coast terminal in Point Comfort, Texas or oil may be transferred at alternate locations to third parties with a terminal fee.
/
19
We have agreements that provide us with field gathering, compression and short-haul transportation services
for our natural gas production and gas lift for our hydrocarbon production under various terms through 2039.
We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one agreement that extends into 2029.
Legal, Environmental Compliance and Other
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of June 30, 2022 and December
31, 2021, we had an estimated reserve of approximately $ii0.1/ million
for certain claims made against us regarding previously divested operations included in Accounts payable and accrued liabilities on our condensed consolidated balance sheets.
As of June 30, 2022 and December 31, 2021, we had AROs of approximately $ii8.4/
million attributable to the plugging of abandoned wells. Additionally, we had $i2.1 million and $i2.3 million of environmental remediation
liabilities assumed in the Lonestar Acquisition as of June 30, 2022 and December 31, 2021, respectively.
Additionally, we have entered into certain contractual arrangements for other products and services and have commitments under information technology licensing and service agreements, among others.
i
Note
12 – Shareholders’ Equity
Capital Stock
Prior to the Lonestar Acquisition, the Company’s authorized capital stock consisted of i115,000,000 shares including (i) i110,000,000
shares of common stock, par value $i0.01 per share and (ii) i5,000,000 shares of Series A Preferred Stock, par value $i0.01
per share.
On October 6, 2021, in connection with the consummation of the Lonestar Acquisition, the Company effected a recapitalization, pursuant to which (i) the Company’s common stock was renamed and reclassified as Class A Common Stock, (ii) the authorized number of shares of capital stock of the Company was increased to i145,000,000
shares, (iii) i30,000,000 shares of Class B Common Stock was authorized, (iv) all i225,489.98 outstanding shares of the Series A Preferred Stock were exchanged
for i22,548,998 newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled.
As of June 30, 2022, the Company had itwo
classes of common stock: Class A Common Stock and Class B Common Stock. The holders of record of Class A Common Stock and Class B Common Stock vote together as a single class on all matters on which holders of Class A Common Stock and Class B Common Stock are entitled to vote; except that certain directors are elected by holders of a majority of the shares of Class B Common Stock voting as a separate class.
The holders of Class A Common Stock have no preemptive rights to purchase shares of Class A Common Stock. Shares of Class A Common Stock are not subject to any redemption or sinking fund provisions and are not convertible into any of the Company’s other securities. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up,
holders of Class A Common Stock will share equally in the assets remaining after it pays its creditors and preferred shareholders. Holders of Class A Common Stock are entitled to receive dividends when and if declared by the Board of Directors.
Shares of Class B Common Stock are non-economic interests in the Company, and no dividends can be declared or paid on the Class B Common Stock. The holders of Class B Common Stock have no preemptive rights to purchase shares of Class B Common Stock. Shares of Class B common stock are not subject to any redemption or sinking fund provisions. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, after payment or provision for payment of its debts and other liabilities, the holders of
Class B Common Stock will be entitled to receive, out of its assets or proceeds thereof available for distribution to our shareholders, before any distribution of such assets or proceeds is made to or set aside for the holders of Class A Common Stock and any other of the Company’s stock ranking junior to the Class B Common Stock as to such distribution, payment in full in an amount equal to $i0.01 per share of Class B Common Stock. With the exception of the aforementioned distribution, the holders of
shares of Class B Common Stock will not be entitled to receive any of the Company’s assets in the event of its voluntary or involuntary liquidation, dissolution or winding up.
The Company’s Class B Common Stock is not convertible into any of the Company’s other securities. However, if a holder exchanges one common unit of the Partnership, for one share of the Company’s Class A Common Stock, it must also surrender to the Company a share of its Class B Common Stock for each common unit exchanged.
As
of June 30, 2022, the Company had (i) i110,000,000 authorized shares of Class A Common Stock and ii20,483,112/
shares of Class A Common Stock issued and outstanding, (ii) i30,000,000 authorized shares of Class B Common Stock and ii22,548,998/
shares of Class B Common Stock issued and outstanding, and (iii) i5,000,000 authorized shares of preferred stock, par value $i0.01 per share, and iino/
shares of preferred stock were issued or outstanding.
/
20
As of June 30, 2022, the Company had not paid any cash dividends on its Class A Common Stock. However, see Note 15 for details on dividends declared subsequent to June 30, 2022. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. The
Company’s Credit Facility and the Indenture have restrictive covenants that limit its ability to pay dividends.
Share Repurchase Program
On April 13, 2022, our Board of Directors approved a share repurchase program that authorized the Company to repurchase up to $i100 million
of its outstanding Class A Common Stock. The share repurchase authorization was effective immediately and was valid through March 31, 2023.
The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions, or by other means in accordance with federal securities laws. The Company intends to fund repurchases from available working capital and cash provided by operating activities. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including among other things, our earnings, liquidity, capital requirements, financial condition, management’s
assessment of the intrinsic value of the Class A Common Stock, the market price of the Company's Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements and other factors deemed relevant. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice.
During the three and six months ended June 30, 2022, we repurchased ii680,876/
shares of our Class A Common Stock at a total cost of $ii25.0/
million and at an average purchase price of $ii36.74/
which was recorded to Class A common stock and Paid-in capital on our condensed consolidated balance sheets. As of June 30, 2022, the remaining authorized repurchase amount under the share repurchase program was $i75.0 million. Subsequently, on July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $i100 million
to $i140 million and extended the term of the program through June 30, 2023.
As discussed above and in Note 13, in the three months ended June 30, 2022, we repurchased shares of our Class A Common Stock of the
Company and issued shares of our Class A Common Stock related to the vesting of employees’ share-based compensation resulting in a change in the proportionate share of Common Units held by the Company relative to Juniper. As such, we recognized an adjustment to the carrying amount of noncontrolling interest and a corresponding adjustment to Class A Common Shareholders’ equity of $ii6.5/
million to reflect the revised ownership percentage of total equity.
i
The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:
Net income (loss) attributable to common shareholders
$
i71,184
$
i3,045
$
i61,199
$
(i10,527)
Transfers
from the noncontrolling interest, net 1
i6,498
N/A
i6,498
N/A
Change
from net income (loss) attributable to common shareholders and net transfers to Noncontrolling interest
$
i77,682
$
i3,045
$
i67,697
$
(i10,527)
_____________________________________________
1
The three and six months ended June 30, 2022includes a net transfer of $ii6.5/
million from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income (loss) and a corresponding decrease to the proportionate share of net income (loss) attributable to common shareholders.
/i
Note
13 – Share-Based Compensation and Other Benefit Plans
Share-Based Compensation
We reserved i4,424,600 shares of Class A Common Stock for issuance under the Ranger Oil Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of i811,573
RSUs and i664,414 PRSUs have been granted to employees and directors through June 30, 2022.
We recognized expense attributable to the RSUs and PRSUs of $i3.0 million
for the six months ended June 30, 2022 and $i3.2 million, including approximately $i1.9 million as a result of a change-in-control
event associated with the Juniper Transactions for the three months ended June 30, 2021. We recognize share-based compensation expense as a component of G&A expenses in our condensed consolidated statements of operations.
/
21
Time-Vested Restricted Stock Units
i
The
table below summarizes activity for the six months ended June 30, 2022 with respect to awarded RSUs:
Compensation
expense for RSUs is recognized on a straight-line basis over the applicable vesting period, which is generally over a ithree-year period. As of June 30, 2022, we had $i2.5 million
of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of i2.07 years.
Performance-Based Restricted Stock Units
The table below summarizes activity for the six months ended June 30, 2022 with respect to awarded PRSUs:
Compensation
expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2022 and 2021 grants and graded-vesting for the 2020 and 2019 grants, over a range of less than one to ithree years. Compensation expense for PRSUs with a performance condition is recognized on a straight-line basis over ithree
years when it is considered probable that the performance condition will be achieved and such grants are expected to vest. PRSUs with a market condition do not allow for the reversal of previously recognized expense, even if the market condition is not achieved and no shares ultimately vest.
The 2022 and 2021 PRSU grants are based 50% on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the ithree-year
performance period. The 2022 and 2021 PRSUs cliff vest from i0% to i200%
of the original grant at the end of a ithree-year performance period based on satisfaction of the respective underlying conditions.
Vesting of PRSUs granted in 2020 and 2019 range from i0%
to i200% of the original grant based on TSR relative to a defined peer group over the ithree
year performance period. As TSR is deemed a market condition, the grant-date fair value for the 2019, 2020 and a portion of the 2021 and 2022 grants is derived by using a Monte Carlo model. iThe ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2022, 2021, 2020 and 2019 are presented as follows:
2022
2021
1
2020 1
2019
Expected volatility
i134.98%
to i138.75%
i131.74%
to i134.74%
i101.32%
to i117.71%
i49.9
%
Dividend
yield
i0.0
%
i0.0
%
i0.0
%
i0.0
%
Risk-free
interest rate
i2.59
%
i0.22%
to i0.29%
i0.18%
to i0.51%
i1.66
%
Performance
period
2022-2024
2021-2023
2020-2022
2020-2022
_______________________
1 One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above.
As of June 30, 2022, we had $i14.3 million
of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of i2.25 years.
22
Other Benefit Plans
We
maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized expense attributable to the 401(k) Plan of $i0.2 million and $i0.4
million for the three and six months ended June 30, 2022, respectively, and $i0.1 million and $i0.3
million for the three and six months ended June 30, 2021, respectively. The charges for the 401(k) Plan are recorded as a component of G&A expenses in our condensed consolidated statements of operations.
We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to January 1, 2000. The combined expense recognized with respect to these plans was less than $iiii0.1///
million for each of the three and six months ended June 30, 2022 and 2021. The charges for these plans are recorded as a component of Other income (expense) in our condensed consolidated statements of operations.
i
Note 14 – Earnings Per Share
Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders,
excluding net income or loss attributable to Noncontrolling interest, by the weighted average common shares outstanding for the period.
In computing diluted earnings (loss) per share, basic net earnings (loss) per share is adjusted based on the assumption that dilutive RSUs and PRSUs have vested and outstanding Common Units (and shares of Class B Common Stock, par value $i0.01 per share (“Class B Common Stock”) as applicable to the six months ended June 30, 2022 and Series A Preferred
Stock, par value $i0.01 per share (“Series A Preferred Stock”) as applicable to the six months ended June 30, 2021) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to common shareholders is adjusted due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the six months ended June 30, 2022
and Series A Preferred Stock as applicable to the six months ended June 30, 2021) held by the Noncontrolling interest.
i
The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented:
Net
(income) loss attributable to Noncontrolling interest
(i76,856)
(i4,551)
(i66,180)
i1,898
Net
income (loss) attributable to common shareholders for Basic EPS
i71,184
i3,045
i61,199
(i10,527)
Adjustment
for assumed conversions and elimination of Noncontrolling interest net income (loss)
i521
i4,551
i432
(i1,898)
Net
income (loss) attributable to common shareholders for Diluted EPS
$
i71,705
$
i7,596
$
i61,631
$
(i12,425)
Denominator:
Weighted
average shares outstanding used in Basic EPS
i20,887
i15,311
i20,996
i15,287
Effect
of dilutive securities:
Common Units and Series A Preferred Stock or Class B Common Stock, as applicable, that are exchangeable for common shares 1
i—
i22,549
i—
i—
RSUs
and PRSUs
i627
i512
i608
i—
Weighted
average shares outstanding used in Diluted EPS 2
i21,514
i38,372
i21,604
i15,287
_______________________
1 In
connection with the Juniper Transactions in January 2021, we issued shares of Series A Preferred Stock. In October 2021, the Company effected a recapitalization and the Series A Preferred Stock were exchanged with Class B Common Stock and the designation of the Series A Preferred Stock was cancelled.
2 For the three and six months ended June 30, 2022, approximately ii22.5/ million
potentially dilutive Common Units (and the associated ii22.5/ million
Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the six months ended June 30, 2021, approximately i22.8 million potentially dilutive securities represented by approximately i22.5
million Common Units (and the associated approximately i0.2 million shares of Series A Preferred Stock) as well as approximately i0.3
million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.
//
23
i
Note
15 – Subsequent Events
Acquisitions
On May 3, 2022, we entered into separate agreements (the “PSAs”) to acquire oil and gas producing properties in the Eagle Ford shale contiguous to our existing assets. Upon signing the PSAs, the Company paid approximately $i6.4 million as a deposit into a third-party escrow account and is classified
as cash flows from investing activities in the consolidated statements of cash flows. The transactions closed on July 1, 2022 for aggregate cash consideration of $i61.0 million, inclusive of the deposit paid and subject to customary purchase price adjustments.
Also in July 2022, we closed on the acquisitions of certain oil and gas producing properties in the Eagle Ford Shale, comprised primarily of additional working interests in Ranger-operated
wells. The aggregate cash consideration paid was $i28.5 million and the acquisitions are subject to customary purchase price adjustments.
Asset Disposition
On July 22, 2022, we closed on the sale of the corporate office building acquired in connection with the Lonestar Acquisition that was classified as Assets held for sale on the condensed consolidated balance sheets as of June
30, 2022 and December 31, 2021. Gross proceeds were $i11.0 million with costs to sell of approximately $i0.8 million,
and included the payoff of the related mortgage debt and accrued interest of $i8.4 million for total net proceeds of $i1.8 million.
Dividends
/
On
July 7, 2022, the Company’s Board of Directors declared a cash dividend of $i0.075 per share of Class A Common Stock, payable on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022.
24
Forward-Looking
Statements
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We use words such as “anticipate,”“guidance,”“assumptions,”“projects,”“estimates,”“expects,”“continues,”“intends,”“plans,”“believes,”“forecasts,”“future,”“potential,”“may,”“possible,”“could” and variations of such words or similar expressions to identify forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include,
but are not limited to, the following:
•risks related to the fourth quarter 2021 acquisition of Lonestar Resources US Inc, including the risk that the benefits of the acquisition may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to integration-related issues;
•risks related to other completed acquisitions and dispositions, including our ability to realize their expected benefits;
•risks related to pending acquisitions, including the risk that the transactions may be delayed or not be consummated or the risk the transactions could distract management from ongoing business operations or cause us to incur substantial costs;
•the decline
in, sustained market uncertainty of, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural gas;
•the continued impact of the COVID-19 pandemic, economic slowdown, governmental actions, stay-at-home orders and interruptions to our operations or our customer’s operations, including as a result of any resurgence or new variant;
•risks related to and the impact of actual or anticipated other world health events;
•our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash flows from operations or to obtain adequate financing, including access to the capital markets, to fund our capital expenditures and meet working capital needs;
•our
ability to access capital, including through lending arrangements and the capital markets, as and when desired;
•negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;
•plans, objectives, expectations and intentions contained in this report that are not historical;
•our ability to execute our business plan in volatile commodity price environments;
•our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;
•changes to our drilling and development program;
•our
ability to generate profits or achieve targeted reserves in our development operations;
•our ability to meet guidance, market expectations and internal projections, including type curves;
•any impairments, write-downs or write-offs of our reserves or assets;
•the projected demand for and supply of oil, NGLs and natural gas;
•our ability to contract for drilling rigs, frac crews, materials, supplies and services at reasonable costs;
•our ability to repurchase shares pursuant to our announced share repurchase program or declare dividends;
•our
ability to renew or replace expiring contracts on acceptable terms;
•our ability to obtain adequate pipeline transportation capacity or other transportation for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices;
•the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and gas reserves;
•use of new techniques in our development, including choke management and longer laterals;
•drilling, completion and operating risks, including adverse
impacts associated with well spacing and a high concentration of activity;
•our ability to compete effectively against other oil and gas companies;
•leasehold terms expiring before production can be established and our ability to replace expired leases;
25
•environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;
•the timing of receipt of necessary regulatory permits;
•the effect of commodity and financial derivative arrangements
with other parties and counterparty risk related to the ability of these parties to meet their future obligations;
•the occurrence of unusual weather or operating conditions, including force majeure events;
•our ability to retain or attract senior management and key employees;
•our reliance on a limited number of customers and a particular region for substantially all of our revenues and production;
•compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;
•physical, electronic and cybersecurity breaches;
•risks
relating to our organizational structure, including the Partnership’s obligations with respect to tax distributions;
•uncertainties and economic events relating to general domestic and international economic and political conditions, such as political tensions or war;
•the impact and costs associated with litigation or other legal matters;
•sustainability initiatives; and
•other factors set forth in our periodic filings with the Securities and Exchange Commission, or SEC, including the risks set forth in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 and our Quarterly Reports on Form 10-Q for the quarterly periods
ended March 31, 2022 and June 30, 2022.
Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result
of new information, future events or otherwise, except as may be required by applicable law.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of the financial condition and results of operations of Ranger Oil Corporation and its consolidated subsidiaries (“Ranger,”“Ranger Oil,” the “Company,”“we,”“us” or “our”) should be read in conjunction with our condensed consolidated financial statements and notes thereto included in Part I, Item 1, “Financial Statements.” All dollar amounts presented in the tables that follow are in thousands unless otherwise
indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain amounts for the prior period have been reclassified to conform to the current period presentation. References to “quarters” represent the three months ended June 30, 2022 or 2021, as applicable.
This section of the Form 10-Q discusses the results of operations for the three and six months ended June 30, 2022 compared to the three and six months ended June 30, 2021 unless otherwise indicated. On October 5, 2021, the Company
acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of Ranger Oil (the “Lonestar Acquisition”). The results of operations of Lonestar are reflected in our accompanying condensed consolidated financial statements for the three and six months ended June 30, 2022. Results for the three and six months ended June 30, 2021 reflect the financial and operating results of Ranger Oil and do not include the financial and operating results of Lonestar. As such, our historical results of operations are not comparable from period to period.
26
Overview
and Executive Summary
We are an independent oil and gas company focused on the onshore development and production of crude oil, natural gas liquids (“NGLs”), and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale in South Texas.
Recent Developments
Share Repurchase Program
On April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $100 million of its outstanding Class A Common Stock through March 31, 2023. On July
7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023.
During the three and six months ended June 30, 2022, we repurchased 680,876 shares of our Class A Common Stock at a total cost of $25.0 million and at an average purchase price of $36.74. During July 2022, we repurchased an additional 672,985 shares of our Class A Common Stock at an average price of $30.57 for a total cost of $20.6 million.
See Note 12 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.
Dividends
On July
7, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock, payable on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022.
Recent Acquisitions
In June and July 2022, we closed on several acquisitions of oil and gas producing properties in the Eagle Ford Shale, comprised of additional working interests in Ranger-operated wells and adjacent producing assets and undeveloped acreage for aggregate preliminary cash consideration totaling $135.5 million subject to customary purchase price adjustments.
See Note 3 and Note 15 to the condensed consolidated financial
statements included in Part I, Item 1, “Financial Statements” for additional information on our acquisitions.
Increased Borrowing Base of Credit Facility
On June 1, 2022, our borrowing base under the Credit Facility increased to $875 million from $725 million with aggregate elected commitments remaining at $400 million.
See Note 7 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our debt.
Industry Environment and Recent Operating and Financial Highlights
Commodity Price and Other Economic Conditions
As an oil and gas development and production company, we are exposed
to a number of risks and uncertainties that are inherent to our industry. In addition to such industry-specific risks, the global public health crisis associated with COVID-19 created uncertainty for global economic activity. Beginning in March 2020, the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy, which directly impacted our industry and the Company. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices.
27
A high level of uncertainty remains regarding the volatility of energy
supply and demand as the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) continued to execute its strategy throughout 2021 to gradually increase production. In August 2022, OPEC+ announced its intent to increase output targets by 100,000 bbls per day in September after raising it by 648,000 bbls per day in July and August. Most recently, WTI crude oil prices have surged but remain volatile, closing at over $120 per bbl during second quarter 2022 as a result of the Russia-Ukraine conflict and related sanctions and concerns that it might result in significant oil supply shortages. In response, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, including releasing emergency oil reserves. Higher energy prices, along with the global supply chain issues and other factors, have increased inflation, which has led or may
lead to increased costs of services and certain materials necessary for our operations.
Our crude oil production is sold at a premium or deduct differential to the prevailing NYMEX West Texas Intermediate (“NYMEX WTI”) price. The differential reflects adjustments for location, quality and transportation and gathering costs, as applicable. All of our crude oil volumes are sold under Magellan East Houston (“MEH”) pricing, which historically has been at a premium to NYMEX WTI.
Similar to crude prices, natural gas prices have jumped substantially and remain volatile as a result of the Russia-Ukraine conflict, with NYMEX Henry Hub (“NYMEX HH”) closing as low as $5.47 per Mcf and as high as $9.46 per Mcf during second quarter 2022. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and
demand relationships in that region or locality. Similar to crude oil, our natural gas production price has a premium or deduct differential to the prevailing NYMEX HH price primarily due to differential adjustments for the location and the energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual interaction of supply and demand.
A summary of these pricing differentials is provided in the discussion of “Results of Operations – Realized Differentials” that follows.
In addition to the volatility of commodity prices, we are subject to inflationary and other factors that have resulted in higher costs for products, materials and services that we utilize in both our capital projects
and with respect to our operating expenses. In 2021, we took certain actions with vendors and other service providers to secure products and services at fixed prices and to pay for certain materials and services in advance in order to lock in favorable costs but we have continued to experience higher costs and this may be exacerbated in the future.
Capital Expenditures, Development Progress and Production
As of June 30, 2022, we operated three drilling rigs and during the six months ended June 30, 2022, we incurred capital expenditures of approximately $207.0 million, of which $204.9 million was directed to drilling and completion projects. During the second quarter 2022, a total of 13 gross (12.3 net) wells were completed and turned in line.
As
of July 29, 2022, we had approximately 192,600 gross (159,600 net) acres in the Eagle Ford, net of expirations, of which approximately 95% is held by production.
Total sales volume for the second quarter 2022 was 3,502 thousand barrels of oil equivalent (“Mboe”), or 38,479 barrels of oil equivalent (“boe”) per day, with approximately 71%, or 2,502 thousand barrels of oil (“Mbbl”), of sales volume from crude oil, 15% from NGLs and 14% from natural gas.
28
Commodity Hedging Program 1
As of July 29, 2022,
we have hedged a portion of our estimated future crude oil and natural gas production from July 1, 2022 through the first half of 2024. The following table summarizes our net hedge position for the periods presented:
3Q2022
4Q2022
1Q2023
2Q2023
3Q2023
4Q2023
1Q2024
2Q2024
NYMEX
WTI Crude Swaps
Average Volume Per Day (bbl)
3,000
3,000
2,500
2,400
2,807
2,657
462
462
Weighted
Average Swap Price ($/bbl)
$
73.01
$
69.20
$
54.40
$
54.26
$
54.92
$
54.93
$
58.75
$
58.75
NYMEX
WTI Crude Collars
Average Volume Per Day (bbl)
15,625
15,625
7,917
6,181
4,891
2,446
Weighted
Average Purchased Put Price ($/bbl)
$
59.22
$
61.30
$
55.79
$
50.67
$
70.00
$
65.00
Weighted
Average Sold Call Price ($/bbl)
$
84.70
$
86.98
$
74.85
$
65.65
$
92.37
$
85.75
NYMEX
WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)
7,337
1,630
Weighted
Average Swap Price ($/bbl)
$
1.172
$
1.020
NYMEX HH Swaps
Average
Volume Per Day (MMBtu)
12,500
12,500
10,000
7,500
Weighted Average Swap Price ($/MMBtu)
$
3.745
$
3.793
$
3.620
$
3.690
NYMEX
HH Collars
Average Volume Per Day (MMBtu)
15,679
14,511
6,417
11,538
11,413
11,413
11,538
11,538
Weighted
Average Purchased Put Price ($/MMBtu)
$
3.088
$
2.854
$
6.000
$
2.500
$
2.500
$
2.500
$
2.500
$
2.328
Weighted
Average Sold Call Price ($/MMBtu)
$
4.141
$
3.791
$
10.000
$
2.682
$
2.682
$
2.682
$
3.650
$
3.000
OPIS
Mt Belv Ethane Swaps
Average Volume per Day (gal)
27,717
27,717
98,901
34,239
34,239
34,615
Weighted
Average Fixed Price ($/gal)
$
0.2500
$
0.2500
$
0.2288
$
0.2275
$
0.2275
$
0.2275
_______________________
1 As
of July 29, 2022, we also had 50,000 bbls/month of incremental WTI Long Calls at $125/bbl in August and September 2022 as well as 25,000 bbls/month of incremental WTI Long Puts at $85/bbl in August and September 2022.
29
Results of Operations
The following table sets forth certain historical summary operating and financial statistics for the periods presented:
Realized prices, including effects of derivatives, net 2
Crude
oil ($/bbl)
$
84.43
$
74.00
$
52.70
$
79.29
$
49.18
NGLs ($/bbl)
$
35.10
$
33.40
$
17.87
$
34.27
$
17.44
Natural
gas ($/Mcf)
$
4.08
$
3.96
$
2.71
$
4.02
$
2.77
Aggregate ($/boe)
$
68.87
$
61.08
$
45.93
$
65.03
$
42.86
Production
and lifting costs:
Lease operating ($/boe)
$
5.40
$
5.33
$
4.30
$
5.36
$
4.52
Gathering,
processing and transportation ($/boe)
$
2.47
$
2.66
$
2.29
$
2.56
$
2.40
Production and ad valorem taxes ($/boe)
$
4.79
$
3.87
$
2.97
$
4.34
$
2.98
General
and administrative ($/boe) 3
$
3.04
$
2.88
$
3.09
$
2.96
$
4.91
Depreciation, depletion and amortization ($/boe)
$
15.50
$
14.98
$
12.74
$
15.25
$
12.82
_______________________
1 All
volumetric statistics presented above represent volumes of commodity production that were sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods.
2 Realized prices, including effects of derivatives, net is a non-GAAP measure (see discussion and reconciliation to GAAP measure below in “Results of Operations – Effects of Derivatives”that follows).
3 Includes combined amounts of $0.71, $0.79 and $0.43 per boe for the three months ended June 30, 2022,March
31, 2022 and June 30, 2021, respectively, attributable to share-based compensation and significant special charges, comprised of organizational restructuring, acquisition and integration costs and strategic transaction costs, including costs attributable to the Lonestar Acquisition during the first and second quarters of 2022 as well as costs attributable to our acquisitions in the second quarter of 2022 as described in the discussion of “Results of Operations - General and Administrative” that follows.
30
Sequential Quarterly Analysis
The
following summarizes our key operating and financial highlights for the three months ended June 30, 2022, with comparison to the three months ended March 31, 2022. The year-over-year highlights for the quarterly periods ended June 30, 2022 and 2021 are addressed in further detail in the discussions that follow below in Year over Year Analysis of Operating and Financial Results.
•Daily sales volume increased to 38,479 boe per day from 37,752 boe per day with 12.3 net wells turned in line for the second quarter 2022 compared to 8.9 net wells turned in line for the first quarter 2022. Total sales volume increased 3% to 3,502 Mboe from 3,398 Mboe.
•Product
revenues increased 23% to $313.4 million from $255.6 million as a result of 19% higher aggregate realized prices and 3% higher total sales volumes. Crude oil realized prices were 17% higher, or $39.9 million, coupled with higher crude oil sales volume, or $6.9 million. NGL revenues were higher due to 2% higher total sales volume, or $0.4 million, and 10% higher realized prices, or $1.7 million. Natural gas revenues were 73% higher as a result of 66% higher realized prices and 4% higher volume for an overall increase of $8.9 million.
•Production and lifting costs, consisting of Lease operating expenses (“LOE”) and Gathering, processing and transportation expenses (“GPT”), increased on an absolute basis to $27.5 million from $27.1 million and decreased on a per unit basis to $7.87 per boe from $7.99 per boe. The per unit basis decrease is due to the effects of 3% higher sales volume.
•Production
and ad valorem taxes increased on an absolute and per unit basis to $16.8 million and $4.79 per boe from $13.1 million and $3.87 per boe, respectively, due to the overall effects of 19% higher aggregate realized product pricing.
•General and administrative (“G&A”) expenses increased on an absolute and per unit basis to $10.6 million and $3.04 per boe from $9.8 million and $2.88 per boe, respectively, primarily due to $1.3 million higher consulting and professional services fees and $1.1 million increased compensation cost associated with employee share-based compensation granted during second quarter 2022, partially offset by $1.3 million lower acquisition and integration costs associated with the Lonestar Acquisition as those efforts were substantially completed by the end of the first quarter 2022.
•Depreciation, depletion
and amortization (“DD&A”) increased on an absolute and per unit basis to $54.3 million and $15.50 per boe during the second quarter 2022 as compared to $50.9 million and $14.98 per boe during the first quarter 2022 due primarily to the oil and gas property acquisitions that closed during the second quarter 2022 and higher development costs.
31
Year over Year Analysis of Operating and Financial Results
Sales Volume
The following tables set forth a summary of our total and average daily sales volumes by product for the periods presented:
Three
Months Ended June 30,
Six Months Ended June 30,
Total Sales Volume 1
2022
2021
Change
% Change
2022
2021
Change
%
Change
Crude oil (Mbbl)
2,502
1,831
671
37
%
4,930
3,300
1,630
49
%
NGLs
(Mbbl)
512
240
272
113
%
1,013
450
563
125
%
Natural
gas (MMcf)
2,926
1,143
1,783
156
%
5,737
2,156
3,581
166
%
Total
(Mboe)
3,502
2,261
1,241
55
%
6,899
4,109
2,790
68
%
Three
Months Ended June 30,
Six Months Ended June 30,
Average Daily Sales Volume 1
2022
2021
Change
% Change
2022
2021
Change
%
Change
Crude oil (bbl/d)
27,496
20,117
7,379
37
%
27,239
18,231
9,008
49
%
NGLs
(bbl/d)
5,624
2,633
2,991
114
%
5,596
2,485
3,111
125
%
Natural
gas (MMcf/d)
32
13
19
146
%
32
12
20
167
%
Total
(boe/d)
38,479
24,844
13,635
55
%
38,118
22,701
15,417
68
%
_______________________
1 All
volumetric statistics represent volumes of commodity production that were actually sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods.
Total sales volume increased 55% and 68% during the three and six month periods in 2022, respectively, when compared to the corresponding periods in 2021 as a result of the Lonestar Acquisition that closed in fourth quarter of 2021 and increased drilling activity. Additionally, during the three month period in 2022, total sales volume increased compared to the corresponding period in 2021 due to 12.3 net wells turned in line in the three month period in 2022 as compared to 8.2 net wells in the corresponding period in 2021.
Approximately 71% of total sales volume during the three and six month periods in 2022 was attributable to crude oil
when compared to approximately 81% and 80%, respectively, during the corresponding periods in 2021. The decrease in the crude oil composition of total sales volume is due primarily to higher gas content of the wells acquired in the Lonestar Acquisition.
Product Revenues and Prices
The following tables set forth a summary of our revenues and prices per unit of volume by product for the periods presented:
Three
Months Ended June 30,
Six Months Ended June 30,
Total Product Revenues
2022
2021
Change
% Change
2022
2021
Change
%
Change
Crude oil
$
273,589
$
116,314
$
157,275
135
%
$
500,321
$
198,227
$
302,094
152
%
NGLs
18,818
4,388
14,430
329
%
35,558
7,950
27,608
347
%
Natural
gas
21,037
3,087
17,950
581
%
33,164
5,920
27,244
460
%
Total
$
313,444
$
123,789
$
189,655
153
%
$
569,043
$
212,097
$
356,946
168
%
Realized
Prices
Three Months Ended June 30,
Six Months Ended June 30,
($ per unit of volume)
2022
2021
Change
% Change
2022
2021
Change
%
Change
Crude oil
$
109.34
$
63.54
$
45.80
72
%
$
101.48
$
60.07
$
41.41
69
%
NGLs
$
36.77
$
18.31
$
18.46
101
%
$
35.11
$
17.68
$
17.43
99
%
Natural
gas
$
7.19
$
2.70
$
4.49
166
%
$
5.78
$
2.75
$
3.03
110
%
Total
$
89.51
$
54.75
$
34.76
63
%
$
82.48
$
51.62
$
30.86
60
%
32
The
following table provides an analysis of the changes in our revenues for the periods presented:
Our
product revenues during the three and six month periods in 2022 increased compared to the corresponding periods in 2021 due to significantly higher prices from continued economic recovery, as well as supply concerns resulting from the Russia-Ukraine conflict. These factors resulted in an increase to the NYMEX WTI benchmark price of 64% for the three and six month periods in 2022 as compared to the corresponding periods in 2021. Also contributing to the higher product revenues was an increase in volumes across all commodities due to the Lonestar Acquisition, with an overall increase in Mboe of 55% and 68% for three and six month periods in 2022, respectively.
Realized Differentials
The following table reconciles our realized price differentials from average NYMEX-quoted prices for WTI crude oil and HH natural gas for the periods presented:
Our
differential to NYMEX WTI for the three and six month periods in 2022, improved by 131% and 87%, respectively, compared to the corresponding periods in 2021 due to more favorable NYMEX Calendar Month Average contractual pricing component and more favorable pricing negotiated with certain new crude purchasers effective early in first quarter 2022. Our differential to NYMEX HH was fairly consistent for the three month period in 2022 as compared to the corresponding period in 2021, while the differential improved for the six month period in 2022 due to more favorable location basis differentials. See also the discussion of Commodity Price and Other Economic Conditions in the Overview above.
Effects of Derivatives
We present realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net as we believe these
measures are useful to management and stakeholders in determining the effectiveness of our price-risk management program that is designed to reduce the volatility associated with our operations. Realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net, are supplemental financial measures that are not prepared in accordance with generally accepted accounting principles (“GAAP”).
33
The following table presents the calculation of our non-GAAP realized prices for crude oil, NGLs and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil and natural gas determined in accordance with GAAP:
Crude
oil realized prices, including effects of derivatives, net ($/bbl)
$
84.43
$
52.70
$
31.73
60
%
$
79.29
$
49.18
$
30.11
61
%
Realized
natural gas liquid prices ($/bbl)
$
36.77
$
18.31
$
18.46
101
%
$
35.11
$
17.68
$
17.43
99
%
Effects
of derivatives, net ($/bbl)
(1.67)
(0.44)
(1.23)
(280)
%
(0.84)
(0.24)
(0.60)
(250)
%
Natural
gas liquids realized prices, including effects of derivatives, net ($/bbl)
$
35.10
$
17.87
$
17.23
96
%
$
34.27
$
17.44
$
16.83
97
%
Realized
natural gas prices ($/Mcf)
$
7.19
$
2.70
$
4.49
166
%
$
5.78
$
2.75
$
3.03
110
%
Effects
of derivatives, net ($/Mcf)
(3.11)
0.01
(3.12)
NM
(1.76)
0.02
(1.78)
NM
Natural gas realized prices, including effects of derivatives, net ($/Mcf)
$
4.08
$
2.71
$
1.37
51
%
$
4.02
$
2.77
$
1.25
45
%
_______________________
NM
- percentage change not meaningful
Effects of derivatives, net include, as applicable to the period presented: (i) current period commodity derivative settlements; (ii) the impact of option premiums paid or received in prior periods related to current period production; (iii) the impact of prior period cash settlements of early-terminated derivatives originally designated to settle against current period production; (iv) the exclusion of option premiums paid or received in current period related to future period production; and (v) the exclusion of the impact of current period cash settlements for early-terminated derivatives originally designated to settle against future period production.
Other operating income, net
Other operating income, net includes fees for marketing and water disposal services that we charge to third parties, net of
related expenses, as well as other miscellaneous revenues and credits attributable to our current operations and gains and losses on the sale or disposition of assets other than our oil and gas properties. In addition, charges attributable to credit losses associated with our trade and joint venture partner receivables are netted within this caption.
The following table sets forth the total Other operating income, net recognized for the periods presented:
Our
marketing fee income increased in the three and six month periods in 2022, as compared to the corresponding periods in 2021 due primarily to the higher commodity-based pricing. Additionally, the six month period in 2022 included a gain on sales of field materials.
34
Lease Operating Expenses
LOE includes costs that we incur to operate our producing wells and field operations. The most significant costs include compression and gas lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment rentals, utilities and supplies, among others.
The following table sets forth
our LOE for the periods presented:
LOE
increased on an absolute basis and per unit basis during three and six month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of the Lonestar Acquisition as well as increased workovers and increased fuel, service and equipment costs driven by higher sales volume.
Gathering, Processing and Transportation
GPT expense includes costs that we incur to gather and aggregate our crude oil and natural gas production from our wells and deliver them via pipeline or truck to a central delivery point, downstream pipelines or processing plants, and blend or process, as necessary, depending upon the type of production and the specific contractual arrangements that we have with the applicable midstream operators. In addition, GPT expense includes short-term rental charges for crude oil storage tanks.
The following
table sets forth our GPT expense for the periods presented:
GPT
expense increased on an absolute basis and per unit basis during the three and six month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of the Lonestar Acquisition, which contributed to the 156% and 166% higher natural gas sales volumes and 37% and 49% higher crude oil sales volumes for the three and six month periods in 2022, respectively. Additionally, for certain of our crude oil volumes gathered, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of $90 per bbl, the gathering rate escalates. As such, with the higher prices during the three and six month periods in 2022, as compared to the corresponding periods in 2021, we incurred higher gathering costs associated with these volumes. These unfavorable variances were partially offset by the effects of an increase in the mix of crude oil volume sold at the wellhead, including the majority of crude oil volumes from the acquired
Lonestar wells, resulting in reduced transportation costs and cost per unit.
Production and Ad Valorem Taxes
Production or severance taxes represent taxes imposed by the states in which we operate for the removal of resources including crude oil, NGLs and natural gas. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties in which we operate, based on the assessed value of our operating properties. The assessments for ad valorem taxes are generally based on published index prices.
The following table sets forth our production and ad valorem taxes for the periods presented:
Production/severance
tax rate as a percent of product revenues
4.6
%
4.7
%
(0.1)
%
(2)
%
4.6
%
4.7
%
(0.1)
%
(2)
%
Production
and ad valorem taxes increased on an absolute basis and per unit basis during the three and six month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of higher volumes from the Lonestar Acquisition. Additionally, Production taxes increased on an absolute and per unit basis due to higher aggregate commodity sales prices during the three and six month periods in 2022.
35
General and Administrative
Our G&A expenses include employee compensation, benefits and other related costs for our corporate management and governance functions, rent and occupancy costs for our corporate facilities, insurance, and professional fees and consulting costs supporting various corporate-level functions,
among others. In order to facilitate a meaningful discussion and analysis of our results of operations with respect to G&A expenses, we have disaggregated certain costs into three components as presented in the table below. Primary G&A encompasses all G&A costs except share-based compensation and certain special charges that are generally attributable to stand-alone transactions or corporate actions that are not otherwise in the normal course.
The following table sets forth the components of our G&A expenses for the periods presented:
Acquisition/integration
and strategic transaction costs
435
—
435
100
%
2,178
4,655
(2,477)
(53)
%
Total
G&A expenses
$
10,635
$
6,985
$
3,650
52
%
$
20,414
$
20,162
$
252
1
%
Per
unit ($/boe)
$
3.04
$
3.09
$
(0.05)
(2)
%
$
2.96
$
4.91
$
(1.95)
(40)
%
Per
unit ($/boe) excluding share-based compensation and other special charges identified above
$
2.33
$
2.66
$
(0.33)
(12)
%
$
2.21
$
2.94
$
(0.73)
(25)
%
Our
total G&A expenses were higher on an absolute basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to increased headcount discussed below and higher share-based compensation cost but relatively flat on a per unit basis due to a 55% increase in total volumes in 2022. Total G&A was relatively flat on an absolute basis for the six month period in 2022 when compared to the corresponding period in 2021 but decreased on a per unit basis due to a 68% increase in total volumes in 2022.
Our primary G&A expenses increased on an absolute basis during the three and six month periods in 2022 as compared to the corresponding periods in 2021 due primarily to increased headcount following the Lonestar Acquisition and the impact of salary increases effective January 1, 2022. Primary G&A expenses decreased on a per unit basis
due to higher overall sales volumes in 2022.
Share-based compensation charges during the periods presented are attributable to the amortization of compensation cost, net of forfeitures, associated with the grants of time-vested restricted stock units (“RSUs”), and performance-based restricted stock units (“PRSUs”). The grants of RSUs and PRSUs are described in greater detail in Note 13 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements.” As a result of the Juniper Transactions, all of the RSUs granted before 2019 vested and an incremental charge of approximately $1.9 million was recorded during the first quarter 2021. All of our share-based compensation represents non-cash expenses.
Depreciation, Depletion and Amortization
DD&A expense includes charges for the allocation
of property costs based on the volume of production, depreciation of fixed assets other than oil and gas assets as well as the accretion of our asset retirement obligations.
The following table sets forth total and per unit costs for DD&A expense for the periods presented:
DD&A
expense increased on an absolute and a per unit basis during the three and six month periods in 2022 as compared to the corresponding periods in 2021. Higher production volume provided for an increase of $15.8 million and $35.8 million and a higher DD&A rate resulted in an increase of $9.7 million and $16.8 million, for the three and six month periods in 2022, respectively. The higher DD&A rate in 2022 is primarily due to the Lonestar Acquisition, which contributed to an increase in our total proved reserves at a higher relative cost per boe as compared to the corresponding periods in 2021.
36
Impairment of Oil and Gas Properties
We assess our oil and gas properties on a quarterly
basis based on the results of a comparison of the unamortized cost of our oil and gas properties, net of deferred income taxes, to the sum of our estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”) in accordance with the full cost method of accounting for oil and gas properties.
We did not record an impairment of our oil and gas properties during the three and six month periods in 2022. We recorded an impairment of $1.8 million in the six months ended June 30, 2021 as a result of capitalized costs of oil and gas properties exceeding the ceiling test in the first quarter of 2021. The impairment in 2021 was the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by the respective quarterly Ceiling Test under the full cost method of
accounting for oil and gas properties.
Interest Expense
Interest expense for periods in 2022 includes charges for outstanding borrowings under the Credit Facility derived from internationally recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. Also included are the amortization of issuance costs capitalized attributable to the Credit Facility and the 9.25% Senior Notes due 2026 and accretion of original issue discount (“OID”) on the 9.25% Senior Notes due 2026.
Interest expense for the periods in 2021 includes charges for outstanding borrowings under the Credit Facility and the Second Lien Credit Agreement, dated September 29, 2017 (the “Second Lien Term Loan”)
which was repaid in full in October 2021, as well as amortization of their respective issuance costs capitalized. Also included is the accretion of OID on the Second Lien Term Loan.
In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage.
The following table summarizes the components of our interest expense for the periods presented:
Total interest expense,
net of capitalized interest
$
11,038
$
5,303
$
5,735
108
%
$
21,735
$
10,700
$
11,035
103
%
The
increase in interest expense during the three month period in 2022 is primarily attributable to interest incurred in the amount of $9.2 million for the 9.25% Senior Notes due 2026 and $1.6 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of $3.4 million for the Second Lien Term Loan and $1.9 million for the Credit Facility as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during the three month period in 2022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding period in 2021.
The increase in interest expense during the six month period in 2022 is primarily attributable to interest incurred in the amount of $18.1 million for the 9.25% Senior Notes due 2026 and $3.3 million for the Credit Facility
compared to interest incurred in the corresponding period in 2021 of $7.0 million for the Second Lien Term Loan and $3.9 million for the Credit Facility as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during the six month period in 2022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding periods in 2021.
37
Derivatives
The gains and losses for our derivatives portfolio reflect changes in the fair value attributable to changes in market values relative to our hedged commodity prices and interest rates.
The following table summarizes the gains and (losses) attributable to our commodity derivatives portfolio and interest rate swaps for the periods presented:
In
the three and six month periods in 2022, commodity prices were significantly higher on an average aggregate basis than those during the corresponding periods in 2021. The derivative losses in the three and six month periods in 2022 and 2021 reflect the decline in the mark-to-market values consistent with the increase in prices attributable to open positions for these periods. Realized settlement payments, net for crude oil, NGL and natural gas derivatives were $74.0 million and $102.5 million for the three and six month periods in 2022, respectively, and $15.7 million and $21.9 million during the three and six month periods in 2021, respectively. We hedge a portion of our exposure to variable interest rates associated with our Credit Facility and, in the three and six month periods in 2021, our Second Lien Term Loan. We paid $0.5 million and $1.4 million of net settlements from our interest rate swaps for the three and six month periods in 2022, respectively, and $1.0 million
and $1.9 million for the corresponding periods in 2021, respectively.
Income Taxes
Income taxes represent our income tax provision as determined in accordance with generally accepted accounting principles. It considers taxes attributable to our obligations for federal taxes under the Internal Revenue Code as well as to the various states in which we operate, primarily Texas, or otherwise have continuing involvement.
The following table summarizes our income taxes for the periods presented:
The
income tax provision resulted in an expense of $1.3 million and an expense of $1.1 million for the three and six month periods in 2022, respectively. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.9%, which is fully attributable to the State of Texas. Our net deferred income tax liability balance of $2.9 million as of June 30, 2022 is also fully attributable to the State of Texas and primarily related to property.
The income tax provision resulted in an expense of $0.2 million and a benefit of $0.1 million for the three and six month periods in 2021, respectively. The federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 1.1% which was fully attributable to the
State of Texas.
38
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. As of June 30, 2022, we had liquidity of $262.8 million, comprised of cash and cash equivalents of $34.5 million and availability under our Credit Facility of $228.3 million (factoring in letters of credit). The Credit Facility provides us up to $1.0 billion in borrowing commitments. The current borrowing base under
the Credit Facility is $875.0 million with aggregate elected commitments of $400.0 million. As of July 29, 2022, we had liquidity of $175.0 million, comprised of cash and cash equivalents of $15.7 million and availability under the Credit Facility of $159.3 million (factoring in letters of credit).
Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been impacted by the COVID-19 pandemic and the Russia-Ukraine conflict and related instability in the
global energy markets, as well as recession fears that impacts demand. In order to mitigate this volatility, we utilize derivative contracts with a number of financial institutions, all of which are participants in our Credit Facility, hedging a portion of our estimated future crude oil, NGLs and natural gas production through the first half of 2024. The level of our hedging activity and duration of the financial instruments employed depends on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.
From time to time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities. We maintain an effective shelf registration statement to allow for optionality.
Capital
Resources
We expect full year 2022 drilling and completions capital expenditures of between $440 and $470 million. We plan to fund our 2022 capital program and our operations for the next twelve months primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our capital spending and operations for at least the next twelve months; however, future cash flows are subject to a number of variables including the length and magnitude of the current global economic uncertainties associated with the COVID-19 pandemic, Russia-Ukraine conflict and related instability in the global energy markets.
Additionally,
we have other obligations primarily consisting of our outstanding debt principal and interest obligations, derivative instruments, service agreements, operating leases, and asset retirement and environmental obligations, all of which are customary in our business. See Note 11 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for more details related to these obligations. The Partnership is also required in certain circumstances to make certain tax distributions to its partners, which may impact cash flow from operations for the Company, as discussed below under “Tax Distributions.”
Dividends
On July 7, 2022, the
Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock, payable on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. We expect to fund dividends and distributions from available working capital and cash provided by operating activities.
Share Repurchase Program
In April 2022, we announced that the Board of Directors approved a share repurchase program under which we were authorized to repurchase up to $100 million of outstanding Class A Common Stock through March 31, 2023. Subsequently on July
7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and
other agreements, and applicable legal requirements. We expect to fund repurchases from available working capital and cash provided by operating activities.
Tax Distributions
Under its partnership agreement, the Partnership is required to make distributions to all of its limited partners pro rata on a quarterly basis and in such amounts as necessary to enable the Company to timely satisfy all of its U.S. federal, state and local and non-U.S. tax liabilities. Additionally, the Partnership is required to make advances to its non-corporate partners in an amount sufficient to enable such partner to timely satisfy its U.S. federal, state and local and non-U.S. tax liabilities (a “Tax Advance”). Any such Tax Advance will be treated as an advance against and, therefore, reduce any future distributions
that such partner is otherwise entitled
39
to receive. The Company’s cash flow from operations and ability to effect share repurchases or cash dividends to our stockholders could be adversely impacted as a result of such cash distributions. Whether and how much Tax Advances are required to be paid is dependent upon the amount and timing of taxable income generated in the future that is allocable to partners and the federal tax rates then applicable. At this time, we are unable to assess whether the Partnership will be required to make Tax Advances for the year ending December 31, 2022 or in future years.
Cash
Flows
The following table summarizes our cash flows for the periods presented:
Net cash provided by (used in) financing activities
(62,106)
9,002
Net increase in cash and cash equivalents
$
10,769
$
36,674
Cash Flows from Operating
Activities. The increase of $175.7 million in net cash provided by operating activities for the six months ended June 30, 2022 compared to the corresponding period in 2021 was primarily attributable to the effect of 2022 cash receipts that were derived from higher average prices and higher total sales volume, partially offset by higher net payments for commodity derivatives settlements and premiums. Additionally, during the six months ended June 30, 2021, there were higher acquisition, integration and strategic transaction costs and executive restructuring costs including severance payments.
Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during the six months ended June 30, 2022 as compared
to the corresponding period in 2021, due primarily to significantly increased drilling and completions activities in 2022, coupled with the current economic impacts from inflation and higher costs, and oil and gas property acquisitions closed and deposits paid in the second quarter of 2022. Early 2021 was impacted by the temporary suspension of the drilling program that began in 2020 due to the global economic downturn associated with COVID-19.
The following table sets forth costs related to our capital expenditures program for the periods presented:
Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs
2,299
1,219
Pipeline,
gathering facilities and other equipment, net 1
(204)
(481)
Total capital expenditures incurred
$
207,034
$
122,853
_______________________
1 Includes certain capital charges to our working interest partners for completion services.
The following table reconciles the total costs of our capital
expenditures program with the net cash paid for capital expenditures as reported in our condensed consolidated statements of cash flows for the periods presented:
Total capital expenditures program costs (from above)
$
207,034
$
122,853
Increase
in accounts payable for capital items and accrued capitalized costs
(30,461)
(22,891)
Net purchases of tubular inventory and well materials 1
1,718
2,851
Prepayments for drilling and completion services, net of (transfers)
(8,784)
(10,023)
Capitalized
internal labor, capitalized interest and other
4,737
2,916
Total cash paid for capital expenditures
$
174,244
$
95,706
_______________________
1 Includes purchases made in advance of drilling.
Cash Flows from Financing Activities. During the six months ended June
30, 2022, we had borrowings of $243.0 million and repayments of $280.0 million under the Credit Facility and $24.1 million of share repurchases. During the six months ended June 30, 2021, we received over $150 million of proceeds from the issuance of equity in connection with the Juniper Transactions. These proceeds were primarily used to (i) fund the repayments of $80.5 million and $50.0 million under the Credit Facility and Second Lien Term Loan, respectively and (ii) pay $9.3 million of transaction and issue costs related to Juniper. The six months ended June 30, 2021 includes an additional repayment of $5 million under the Credit Facility and a $3.8 million quarterly amortization payment under the Second Lien Term Loan.
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Capitalization
The
following table summarizes our total capitalization as of the dates presented:
1
The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of June 30, 2022 and December 31, 2021, these assets were classified as Assets held for sale on the condensed consolidated balance sheets. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 15 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on the sale.
2 Other debt of $2.2 million was extinguished during the six months ended June 30, 2022 and recorded as a gain on extinguishment of debt.
Credit
Facility. As of June 30, 2022, the Credit Facility had a $1.0 billion revolving commitment and an $875 million borrowing base, with aggregate elected commitments of $400 million and a $25 million sublimit for the issuance of letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. Our next borrowing base redetermination is expected to be in August 2022. The Credit Facility is available to us for general corporate purposes including working capital. We had $0.7 million and $0.9 million in letters of credit outstanding as of June 30, 2022 and December
31, 2021, respectively. The maturity date under the Credit Facility is October 6, 2025.
In June 2022, we entered into the Agreement and Amendment No. 12 to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on June 1, 2022, (1) increase the borrowing base from $725 million to $875 million, with aggregate elected commitments remaining at $400 million and (2) replaced LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements.
The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from
1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) effective June 1, 2022, a term SOFR reference rate (a Eurodollar rate, including LIBOR prior to June 1, 2022), plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on SOFR, borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As of June 30, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.98%. Unused commitment fees are charged at a rate of 0.50%.
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The
following table summarizes our borrowing activity under the Credit Facility for the periods presented:
The
Credit Facility is guaranteed by all of the subsidiaries of the borrower (the “Guarantor Subsidiaries”), except for Boland Building, LLC. The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on the ability of the borrower or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries’
assets.
9.25% Senior Notes due 2026. On August 10, 2021, our indirect, wholly-owned subsidiary completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed by ROCC Holdings, LLC (formerly, Penn Virginia Holdings, LLC, hereinafter referred to as “Holdings”), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility.
Covenant Compliance. The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers
the unused portion of the total commitment as a current asset) of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00.
The Credit Facility and the indenture governing the 9.25% Senior Notes due 2026 contain customary affirmative and negative covenants as well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.
As of June 30, 2022, we were in compliance with all of the debt covenants.
See
Note 7 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our debt.
Critical Accounting Estimates
The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2021.
As
described in this Quarterly Report on Form 10-Q as well as the Critical Accounting Estimates disclosures in the Annual Report on Form 10-K, we apply the full cost method to account for our oil and gas properties. At the end of each quarterly reporting period, we perform a Ceiling Test in order to determine if our oil and gas properties have been impaired. For purposes of the Ceiling Test, estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. We had no impairments of our proved oil and gas properties during the first and second quarter of 2022. The carrying value
of our proved oil and gas properties exceeded the limit determined by the Ceiling Test as of March 31, 2021, resulting in a $1.8 million impairment for the six months ended June 30, 2021.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.
Interest
Rate Risk
As of June 30, 2022, we had variable-rate borrowings of $171.0 million under the Credit Facility and fixed-rate borrowings of $400.0 million for the 9.25% Senior Notes due 2026 at interest rates of 4.98% and 9.25%, respectively. Assuming a constant borrowing level under the Credit Facility, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in aggregate interest payments of approximately $1.7 million on an annual basis, excluding the offsetting impact of our interest rate swap derivatives.
Commodity Price Risk
We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial
instruments (such as collars and swaps) to seek to mitigate the price risks associated with fluctuations in commodity prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of crude oil, NGLs and natural gas.
As of June 30, 2022, our commodity derivative portfolio was in a net liability position in the amount of $152.5 million. The contracts associated with this position are with eight counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, in that these
counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.
During the six months ended June 30, 2022, we reported a net commodity derivative loss of $212.9 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized
gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for a further description of our commodity price risk management activities.
The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil and natural gas prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.
Change of 10% per bbl of Crude
Oil ($ in millions)
Increase
Decrease
Effect on the fair value of crude oil derivatives 1
$
(54.7)
$
39.8
Effect of crude oil price changes for the remainder of 2022 on operating income, excluding derivatives 2
$
25.1
$
(23.1)
_______________________
1 Based
on derivatives outstanding as of June 30, 2022.
2 These sensitivities are subject to significant change.
Item 4. Controls and Procedures
(a) Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2022. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the
reports we file or submit under the Exchange Act is recorded, processed, summarized and reported on a timely basis and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial
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Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of June 30, 2022, such disclosure controls and procedures were effective.
(b) Changes in Internal Control Over Financial Reporting
Except as described below, during the quarter ended June
30, 2022, there were no changes to our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
During the quarter ended June 30, 2022, we continued the process of integrating Lonestar into our operations and internal control processes.
Part II. OTHER INFORMATION
Item 1. Legal Proceedings
We are not aware of any material pending legal or governmental proceedings against us, any material proceedings
by governmental officials against us that are pending or contemplated to be brought against us and no such proceedings have been terminated during the period covered by this Quarterly Report on Form 10-Q. See Note 11 to our condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information regarding our legal and regulatory matters.
Item 1A. Risk Factors
There have been no material changes to the risk factors disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 except as follows:
We
cannot assure you that we will pay dividends on our Class A Common Stock, and our indebtedness could limit our ability to pay future dividends on our Class A Common Stock.
We declared our first cash dividend on our Class A Common Stock in July 2022. Any determination to pay dividends to holders of our Class A Common Stock in the future will be subject to applicable law and at the discretion of our board of directors and will depend upon many factors, including our financial condition, results of operations, projections, liquidity, earnings, legal requirements, covenant compliance, restrictions in our existing and any future debt agreements and other factors that our board of directors deems relevant. Our financing arrangements, including the Credit Facility, place certain direct and indirect restrictions on our ability to pay cash dividends. Therefore, there can be no assurance that we will pay any dividends to holders of our
Class A Common Stock or as to the amount of any such dividends, and we may cease such payments at any time in the future. In addition, our historical results of operations, including cash flows, are not indicative of future financial performance, and our actual results of operations could differ significantly from our historical results of operations. We have not adopted, and do not currently expect to adopt, a separate written dividend policy.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table summarizes our repurchase of equity securities during the three months ended June 30, 2022:
Period
Total
Number of Shares Repurchased
Average Price Paid Per Unit
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
Approximate Dollar Value of Shares Yet to be Purchased Under the Publicly Announced Plans or Programs 1
1 On
April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $100 million of its outstanding Class A Common Stock through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023.
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
The cover page of Ranger Oil Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, formatted in Inline XBRL (included within the Exhibit 101 attachments).
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
